Method and Application of Coordinating Solid Wall Stabilizer for Drilling Fluid in Marine Hydrate Drilling with Temperature and Pressure Fields to Stabilize Wellbore

Abstract

The present invention relates to a method and application for synergistically stabilizing the wellbore by using a wellbore wall stabilizer and a temperature-pressure field for marine hydrate drilling mud, belonging to the technical field of natural gas hydrate development. Considering the changes in reservoir mechanical parameters caused by hydrate phase change, formation creep, and the interaction between drilling mud and hydrate reservoirs, the mud cake is embedded in the non-steady mass transfer and heat transfer model to construct a multi-field coupling model of drilling fluid-solid-heat-chemistry for natural gas hydrate in the sea area. The dosage of the drilling fluid wellbore wall stabilizer and parameters such as the temperature and pressure of the drilling fluid are dynamically adjusted. According to the improved Mohr-Coulomb criterion of the hydrate reservoir, the stability state of the wellbore is judged in real time, and the risk of wellbore instability is quickly reduced by dynamically adjusting the drilling fluid parameters (concentration of the wellbore wall stabilizer, drilling fluid temperature or pressure), so as to achieve the stability of the wellbore during drilling in the marine hydrate reservoir.

Description

Technical Field

[0001] The present invention relates to a method for synergistically stabilizing a wellbore with a wellbore wall stabilizer and a temperature-pressure field for marine hydrate drilling drilling fluid and its application, and belongs to the technical field of natural gas hydrate development. Background Art

[0002] Natural gas hydrate is an ice-like cage-shaped crystalline substance formed by water molecules and natural gas molecules under low-temperature and high-pressure environments, also known as "flammable ice", "solid gas", etc. It is recognized as an ideal alternative energy source in the 21st century worldwide due to its high energy density and low pollution. According to incomplete statistics, the carbon content of global hydrates can reach 1.5 trillion tons, accounting for more than 50% of the global carbon content; and the methane content can reach 70 - 200 trillion cubic meters. Methane commercially produced from 15% of natural gas hydrates can meet the energy needs of the entire world for the next 200 years. More than 90% of natural gas hydrates are distributed in submarine formations. Currently, countries around the world are competing fiercely in the research of natural gas hydrate extraction technologies. Strengthening the theoretical and technical research on the efficient extraction of submarine natural gas hydrates and providing technical preparations for commercial extraction are the current urgent needs and tasks.

[0003] During the drilling process in hydrate reservoirs, the reservoir around the wellbore is extremely sensitive to temperature and pressure changes. The invasion of drilling fluid into hydrate reservoirs is an unsteady heat and mass transfer process, involving the coupling of multiple physical fields such as fluid-solid-heat. When the drilling fluid invades the hydrate reservoir under the action of pressure difference, it undergoes heat and mass transfer reactions with the hydrate reservoir and affects the mechanical properties around the wellbore through interactions such as heat conduction, fluid flow, and hydrate phase change, resulting in wellbore instability. Therefore, during the drilling process in deep-water hydrate reservoirs, there is an urgent need for a method to coordinately regulate the formation mechanical parameters and wellbore stability of the drilling fluid and the reservoir temperature and pressure fields to solve the problem of wellbore instability caused by the phase change of hydrates due to the invasion of drilling fluid. Chinese patent document CN112347675B discloses a method for coordinately regulating the phase state of natural gas hydrates in reservoirs by drilling fluid additives and temperature and pressure fields, which uses the particle swarm algorithm to obtain the optimal combination of drilling fluid additive concentration, injection temperature, and displacement to minimize the change in the saturation of natural gas hydrates in the reservoir. However, the above method does not consider the mud cake parameters under the influence of wall stabilizers in the drilling fluid and the change in formation mechanical properties after hydrate decomposition; Chinese patent document CN114965520A provides a device and method for evaluating the stability performance of the wellbore in a hydrate formation during the simulated drilling process, and Chinese patent document CN115408956B provides a method for real-time obtaining of physical and mechanical parameters around the wellbore in a hydrate reservoir drilling, but neither of them considers the influence law of the wall stabilizer of the drilling fluid on heat and mass transfer between the wellbore and the reservoir; Chinese patent document CN118627424A provides a method for calculating the safety density window of a hydrate formation considering the mud cake, but does not consider the influence mechanism of drilling fluid invasion on reservoir mechanical parameters. To sum up, clarifying the influence law of the wall stabilizer of the drilling fluid on the drilling mechanical parameters of marine natural gas hydrates and designing a method for coordinately stabilizing the wellbore by coupling the wall stabilizer with the temperature and pressure fields of marine hydrate reservoirs are one of the key research directions in the current field of natural gas hydrate development technology. Summary of the Invention

[0004] Aiming at the deficiencies of the prior art, the present invention provides a method for coordinately stabilizing the wellbore by using a wall stabilizer for drilling fluid in marine hydrate drilling and the temperature and pressure fields. Considering the changes in reservoir mechanical parameters caused by hydrate phase change, formation creep, and the interaction between the drilling fluid and the hydrate reservoir, the mud cake is embedded in the unsteady heat and mass transfer model, a multi-field coupling model of fluid-solid-heat-chemistry for marine natural gas hydrate drilling is constructed, the dosage of the drilling fluid wall stabilizer and parameters such as the temperature and pressure of the drilling fluid are dynamically adjusted, the stability state of the wellbore is judged in real time according to the improved Mohr-Coulomb criterion for the hydrate reservoir, and the risk of wellbore instability is quickly reduced by dynamically adjusting the drilling fluid parameters (wall stabilizer concentration, drilling fluid temperature or pressure) to achieve the stability of the wellbore during the drilling of marine hydrate reservoirs.

[0005] The technical solution of the present invention is as follows:

[0006] A method for synergistically stabilizing the wellbore with a wellbore wall stabilizer for marine hydrate drilling drilling fluid, comprising the following steps:

[0007] Step S1: Obtain the current drilling parameters and physical property data of the natural gas hydrate reservoir, and establish an unsteady mass and heat transfer model of the wellbore-hydrate reservoir through the unsteady heat transfer model of the wellbore-hydrate reservoir, the multiphase seepage model of the hydrate reservoir, and the intrinsic decomposition kinetics model of the hydrate.

[0008] Preferably, the unsteady heat transfer model of the wellbore-hydrate reservoir is calculated according to the following formula. According to the law of conservation of energy, the solid-phase energy equation containing hydrate phase change is:

[0009] (1)

[0010] In the formula, ϕ wg is the finite porosity of gas-liquid flow in the hydrate reservoir, ϕ wg = ϕ ×(1 - S h ), ϕ is the porosity of the sand body, S h is the saturation of hydrate; t is time; is the density of the solid phase ρ and the specific heat capacity C of the equivalent product, k eh is the equivalent thermal conductivity of the solid phase, and k eh can be solved by volume fraction weighting; T e is the solid-phase temperature; ∆ E h is the decomposition heat of hydrate; h sf is the convective heat transfer coefficient between the solid phase and the fluid; A sf is the specific surface area in the porous medium; T f is the fluid temperature; is the decomposition rate of hydrate in the porous medium, which can be solved by the intrinsic decomposition kinetics model of hydrate (K-B model):

[0011] (2)

[0012] In the formula, M h is the molar mass of hydrate, k d is the intrinsic reaction constant of hydrate, △E is the activation energy of hydrate, R is the gas constant, and T is the thermodynamic temperature. A h is the mass transfer specific surface area of hydrate phase change, p eq and p e are the equilibrium pressure of hydrate under phase equilibrium temperature and pressure conditions and the pore pressure during the formation process, respectively.

[0013] The flow of fluid in porous media involves five forms of heat transfer, namely, energy migration caused by fluid flow, heat conduction inside the fluid, convective heat transfer at the fluid-solid interface, the Joule-Thomson effect of gas, and the energy decomposition of water and gas, as shown in Equation (3). The left side of the equation represents the change in internal energy, and the right side represents the five forms of heat transfer in sequence;

[0014] (3)

[0015] In the formula, k f is the thermal conductivity of the fluid; p is the fluid pressure; and are the rates of free gas and water generated by hydrate decomposition, respectively; C p,g and C p,w are the specific heat capacities at constant pressure of free gas and water, respectively; S 、 ρ and v are the saturation, density, and flow velocity, respectively. The subscripts g and w represent free gas and water; μ JT is the Joule-Thomson effect coefficient;

[0016] In the process of local non-equilibrium heat transfer, the energy control equations of fluid and solid are often closed by constructing a convective heat transfer model at the interface. The expression is:

[0017] (4)

[0018] In the formula, N u is the Nusselt number, d p is the average diameter of sand grains, R e is the Reynolds number, P r is the Prandtl number.

[0019] Preferably, the multiphase seepage model of the hydrate reservoir is calculated according to the following formula. According to the law of conservation of mass, the continuity equations of free gas, water, and hydrate in the porous medium can be expressed as:

[0020] (5)

[0021] (6)

[0022] (7)

[0023] In the formula, k is the effective permeability of the hydrate reservoir, which has an exponential relationship with the hydrate saturation, k = k 0×(1- S h ) N , k 0 is the effective initial permeability of the hydrate reservoir, N is the permeability reduction index related to the pore scale and structure of the hydrate sediment; ρ h is the density of the hydrate; k rw and k rg are the relative permeabilities of the water phase and the gas phase, respectively; μ w and μ g are the viscosities of the water phase and the gas phase, respectively; p w and p g are the pressures of the water phase and the gas phase in the pores, respectively; the subscript h represents hydrate, S h is the hydrate saturation; , and represent the mass change rates of water, gas, and hydrate, respectively; g is the acceleration due to gravity, m / s 2 ; ɸ is the porosity.

[0024] Assuming that the density of water is constant within the reservoir pressure range, the continuity equation of the water phase after conversion is:

[0025] (8)

[0026] In the formula, p c is the capillary force;

[0027] According to the gas state equation, the continuity equation of the gas phase is finally expressed as:

[0028] (9)

[0029] In the formula, M g is the molar mass of the gas; Z is the compressibility factor of the gas.

[0030] By coupling the unsteady heat transfer model of the wellbore - hydrate reservoir, the multiphase seepage model of the hydrate reservoir, and the intrinsic decomposition kinetic model of hydrate, the unsteady mass and heat transfer model of the wellbore - hydrate reservoir is established as:

[0031] (10).

[0032] Step S2: Considering the changes in reservoir mechanical parameters brought about by hydrate phase change, formation creep, and the interaction between drilling fluid and hydrate reservoir, embed the mud cake into the unsteady mass and heat transfer model to construct a multi - field coupling model of gas hydrate drilling flow - solid - heat - chemistry in the sea area.

[0033] In the original state of the formation, hydrate, as an effective cementing component of the formation and the rock skeleton, jointly supports the overlying stress of the formation. When hydrate decomposes, the phase change from solid to fluid state will change the effective stress of the formation, thereby causing the weakening of the formation cementing strength and the deterioration of the formation mechanical properties, and thus it is very likely to cause problems such as formation instability and a large amount of sand production. Considering the continuously changing mechanical properties of the hydrate reservoir, an elastoplastic constitutive equation is used to describe the relationship between stress and strain, and its incremental form is as follows:

[0034] (11)

[0035] In the formula, d σij is the effective stress increment matrix; D ijkl is the elastoplastic matrix tensor of the hydrate formation; d εkl is the reservoir skeleton strain increment matrix;

[0036] The static equilibrium equation can be expressed in the tensor form of effective stress as:

[0037] (12)

[0038] In the formula, σ ij is the reservoir skeleton stress tensor, represents the divergence of the stress tensor in the j direction, α B is the Biot coefficient; δ ijis the Kronecker function; F i is the body force load;

[0039] The relationship between the displacement and the strain can be expressed in tensor form as:

[0040] (13)

[0041] In the formula, ε ij is the reservoir skeleton strain tensor, w is the strain displacement, is the rate of change of the strain displacement along the coordinate i direction, is the rate of change of the strain displacement along the coordinate j direction;

[0042] The changes in the elastic modulus and the internal friction angle caused by the hydrate decomposition will also trigger wellbore instability. Preferably, the relationship between the in-situ internal friction angle and the hydrate saturation is calculated and regressed according to the following formula:

[0043] (14)

[0044] In the formula, φ is the in-situ internal friction angle of the hydrate reservoir.

[0045] Preferably, the relationship between the in-situ cohesion and the hydrate saturation is calculated and regressed according to the following formula:

[0046] (15)

[0047] In the formula, C ( S h ) is the cohesion, C 0 is S h the cohesion when α , β are all empirical coefficients characterizing the in-situ cohesion.

[0048] Preferably, the relationship between the in-situ elastic modulus and the hydrate saturation is calculated and regressed according to the following formula:

[0049] (16)

[0050] In the formula, E ( S h ) is the elastic modulus of the hydrate reservoir, E 0 is S h the elastic modulus when

[0051] During the drilling process, the mud cake, as a key product of the interaction between the wellbore wall and the drilling fluid, plays a non-negligible role in wellbore stability. On the one hand, the porosity and permeability of the mud cake determine its barrier effect on fluid penetration, directly affecting the risks of hydrate decomposition and wellbore failure; on the other hand, the mechanical strength of the mud cake is the microscopic basis for supporting wellbore stability. Therefore, it is necessary to introduce mud cake parameters into the multi-field coupling model to further explore the dynamic correlation between the mud cake and the mechanical properties of the reservoir, so as to achieve a global analysis of wellbore stability.

[0052] Preferably, the dynamic permeability of the mud cake is calculated according to the following formula:

[0053] (17)

[0054] In the formula, λ is the pore-permeability attenuation index, K mc0 is the minimum permeability of the mud cake, K f is the formation permeability.

[0055] The dynamic porosity of the mud cake is calculated according to the following formula:

[0056] (18)

[0057] In the formula, ϕ mc0 is the minimum porosity of the mud cake, ϕ f is the formation porosity.

[0058] The dynamic porosity and permeability are usually interrelated. For example, a decrease in porosity (through compaction and consolidation) will lead to a decrease in permeability. This interaction has a dual positive impact on the mechanical strength of the mud cake: the decrease in porosity will increase the effective stress and enhance the mechanical strength; while the decrease in permeability will reduce the pore connectivity and enhance the inter-particle cementation force, further improving the mechanical strength. Therefore, the change in the dynamic mechanical strength of the mud cake is calculated according to the following formula:

[0059] (19)

[0060] In the formula, σ mc0 is the initial mechanical strength of the mud cake; m and n are the contribution constants of permeability and porosity to the mechanical strength of the mud cake.

[0061] By introducing the changes in reservoir mechanical parameters (such as the internal friction angle, cohesion, and elastic modulus) and the porosity, permeability, and dynamic mechanical strength parameters of the mud cake into the unsteady mass and heat transfer model of the wellbore-hydrate reservoir, a fully coupled relationship among the thermal field, flow field, and force field was established using the multi-physics coupling software COMSOL. In the thermal field, the low porosity and low permeability of the mud cake changed the heat transfer path near the wellbore by modifying the thermal conductivity and heat capacity of the local reservoir area. In the flow field, the barrier effect of the mud cake affected the seepage behavior and pore pressure distribution of the fluid after hydrate decomposition by dynamically correcting the effective permeability and porosity. In the force field, the dynamic mechanical strength of the mud cake, as an important source of wellbore support, acted together with the changes in reservoir mechanical parameters to affect the stress distribution and plastic zone evolution around the wellbore. By comprehensively coupling the reservoir porosity, permeability, and the processes of heat release, fluid flow, and mechanical evolution caused by hydrate decomposition, a multi-field coupling model integrating mass transfer, heat transfer, mechanical behavior, and chemical reactions was finally formed, providing a theoretical basis for studying the mechanism of wellbore instability and stability control during the drilling process of marine natural gas hydrates.

[0062] Step S3: Design a drilling fluid system for marine hydrates. Add different amounts of wellbore stabilizing agents to the drilling fluid, analyze the dynamic evolution laws of the porosity, permeability, and mechanical strength of the mud cake, and clarify the influence mechanism of the wellbore stabilizing agent of the drilling fluid on the reservoir mechanical properties.

[0063] Obtain the existing wellbore stabilizing agents for conventional marine hydrate drilling fluids. Systematically construct a high-performance marine hydrate drilling fluid system with both wellbore stability and reservoir protection by adding lubricants, inhibitors, viscosity increasing and film forming agents, viscosifiers, glass beads, filtrate loss reducers, and reservoir bridging agents. Measure the density and rheological parameters of the drilling fluid and conduct API filtration experiments. Pour the drilling fluid into the filter loss instrument, install filter paper or filter membrane, turn on the equipment, and maintain it running for 30 minutes under the set conditions. Record the cumulative filtrate volume 𝑉 every 1 minute, and calculate the filtration loss. Turn off the equipment, slowly release the pressure, take out the mud cake, measure the thickness at multiple points of the mud cake using a thickness gauge, and take the average value. L ;

[0064] Place the mud cake in an oven, set the temperature (such as 60 °C), dry it to a constant weight, and then measure the porosity of the mud cake using the density method, that is, measure the dry weight ( m d ), and volume ( V ) of the mud cake, calculate the dry density of the mud cake ( ρ d = m d / V ), and calculate the porosity through the density of bentonite in the mud preparation ( ρ s ). is:

[0065] (20)

[0066] In the filtration loss experiment, under the action of a certain pressure difference, the drilling fluid forms a mud cake through a filter paper or a filter membrane, and the filtrate flows out through the mud cake. The flow of the filtrate and the formation process of the mud cake conform to Darcy's law and the filtration loss theory. The permeability of the mud cake affects the passing speed of the filtrate. Conversely, the change of the filtrate volume with time also reflects the permeation characteristics of the mud cake.

[0067] Calculate the permeability of the mud cake according to the filtration loss theory and Darcy's law K is:

[0068] (21)

[0069] Where: V is the filtrate volume, cm³; μ is the plastic viscosity of the drilling fluid, Pa·s; L is the thickness of the mud cake, m; t is the experimental time, s; A is the area of the filter paper, m 2 ; Δ P is the pressure difference, Pa;

[0070] Use the FCP Mud Cake Penetration Tester to measure the mechanical strength of the mud cake. This device can accurately measure its mechanical properties such as compressive strength while maintaining the integrity of the mud cake. Install the mud cake sample to be tested on the test bench of the FCP instrument, ensure that the needle is vertically aligned with the sample surface, select an appropriate load range according to the experimental requirements and calibrate the instrument to ensure the measurement accuracy. After starting the instrument, apply the preset load and record the relationship curve between the penetration depth and the applied force; further preferably, to improve the reliability of the data, each measurement point is tested at least three times repeatedly and the average value is taken. Finally, calculate the compressive strength of the mud cake by analyzing the load-penetration depth curve;

[0071] The compressive strength reflects the bearing capacity of the mud cake under axial pressure. A higher compressive strength indicates that a strong barrier has been formed by the mud cake on the wellbore wall, which helps to prevent accidents such as well collapse and well kick. The compressive strength of the mud cake σ c The calculation formula is:

[0072] (22)

[0073] Where: F max is the maximum load value applied, N; r is the radius of the needle, m;

[0074] Adjust the concentration of the wall-building agent in the drilling fluid, and conduct filtration experiments, porosity measurements, permeability tests, and mechanical strength measurements under the same experimental conditions. By combining the experimental data with the reservoir mechanics theory and the drilling fluid-solid-thermal-chemical multi-field coupling model for marine natural gas hydrates, systematically analyze the dynamic evolution laws of the mud cake porosity, permeability, and mechanical strength, and reveal how the wall-building agent affects the macroscopic mechanical properties of the reservoir by regulating the microscopic structure parameters of the mud cake during the process of optimizing the drilling fluid formula, so as to clarify the influence mechanism of the wall-building agent on the reservoir mechanical properties.

[0075] Step S4: Dynamically adjust the dosage of the wall-building agent in the drilling fluid and the temperature and pressure parameters of the drilling fluid, and judge the wellbore stability state in real time according to the improved Mohr-Coulomb criterion for hydrate formations to achieve the stability of the wellbore during the drilling of marine hydrate reservoirs.

[0076] Preferably, after clarifying the regulation mechanism of the wall-building agent on the microscopic structure of the mud cake and the macroscopic mechanical properties of the reservoir, further dynamically adjust the concentration of the wall-building agent in the drilling fluid and parameters such as the temperature and pressure of the drilling fluid, and combine with the drilling fluid-solid-thermal-chemical multi-field coupling model for marine natural gas hydrates to evaluate the wellbore stability performance in real time. Based on the improved Mohr-Coulomb yield criterion and the wellbore yield expansion rate, quantify the plastic yield range of the wellbore to achieve the optimization of the dynamic regulation scheme and the accurate judgment of the wellbore stability state. Wellbore yield expansion rate = plastic yield distance ∆ r / wellbore radius r 0;

[0077] The basis for judging the wellbore stability by applying the improved Mohr-Coulomb yield criterion for hydrate formations into the drilling fluid-solid-thermal-chemical multi-field coupling model for marine natural gas hydrates:

[0078] (23)

[0079] In the formula: τ is the shear stress, MPa; σ is the confining pressure, MPa;

[0080] Under different stress states, the expression of the critical maximum principal stress of the hydrate formation is:

[0081] (24)

[0082] In the formula, σ 1f is the critical maximum principal stress, σ 3 is the minimum effective principal stress.

[0083] Calculate the maximum effective principal stress through the stress distribution of the reservoir σ 1:

[0084] (25)

[0085] In the formula, P mud is the wellbore drilling fluid pressure, MPa; P rock is the formation pore pressure, MPa; r 0 is the wellbore radius, m; r is the radial distance from the wellbore center, m.

[0086] Calculate the minimum effective principal stress through the stress distribution in the reservoir σ 3:

[0087] (26)

[0088] If σ 1f > σ 1, the formation in this area is in the stage of plastic deformation accumulation. This point is the yield boundary. At this time, the radial distance ∆ from the wellbore center r is the plastic yield distance.

[0089] It can be seen from the Mohr-Coulomb yield criterion of the hydrate formation that the convective heat transfer between the wellbore and the reservoir under the action of the pressure difference causes the decomposition of hydrates in the near-wellbore zone, resulting in the deterioration of the mechanical properties of the reservoir, that is, the reduction of the mechanical parameters around the wellbore, making the near-wellbore zone evolve from elastic strain to plastic yield, and the wellbore yield expansion rate (plastic yield distance ∆ r / wellbore radius r 0) gradually increases with the decomposition of hydrates, leading to wellbore instability.

[0090] The change of the concentration of the drilling fluid solid wall agent can directly affect the porosity, permeability and mechanical strength of the mud cake. Optimize the mud cake parameters by adjusting the dosage of the solid wall agent, so as to enhance the plugging and bearing performance of the near-well area of the reservoir; at the same time, change the temperature and pressure parameters of the drilling fluid to inhibit the decomposition rate of hydrates and reduce the pressure difference between the wellbore and the reservoir, and reduce the range of plastic yield of the wellbore wall; based on the multi-field coupling model of drilling fluid-solid-thermal-chemical for natural gas hydrates in the sea area, combined with the temperature and pressure conditions of the reservoir and wellbore, the concentration of the solid wall agent, the performance of the mud cake and other parameters, calculate the wellbore yield expansion rate. When the yield expansion rate exceeds the set threshold (such as 0.3), quickly reduce the risk of wellbore instability by dynamically adjusting the drilling fluid parameters (concentration of the solid wall agent, drilling fluid temperature or pressure), and realize the stability of the wellbore wall during the drilling of natural gas hydrates in the sea area. The drilling fluid parameters include the concentration of the solid wall agent, the drilling fluid temperature, and the drilling fluid pressure.

[0091] A method for synergistically stabilizing the wellbore with a wellbore wall stabilizer and temperature-pressure field for marine hydrate drilling drilling fluid, including a data acquisition module, a data analysis module, and a dynamic regulation module; the data acquisition module is used to collect key performance parameters of the hydrate reservoir, wellbore drilling fluid, and wellbore mud cake; the data analysis module is used to execute the method for synergistically stabilizing the wellbore with the wellbore wall stabilizer and temperature-pressure field, establish a multi-field coupling model of fluid-solid-thermal-chemical in marine natural gas hydrate drilling, and calculate the wellbore yield expansion rate based on the improved Mohr-Coulomb yield criterion to quantify the wellbore stability state; the dynamic regulation module realizes precise regulation of wellbore stability by adjusting the concentration of the wellbore wall stabilizer in the drilling fluid and the temperature-pressure parameters of the drilling fluid, providing theoretical support and technical guarantee for the prevention and dynamic control of wellbore instability during marine hydrate drilling.

[0092] The third aspect of the present invention provides a computer-readable storage medium, on which a program is stored, and when the program is executed by a processor, it realizes the steps in the method for synergistically stabilizing the wellbore with a wellbore wall stabilizer and temperature-pressure field for marine hydrate drilling as described above.

[0093] The fourth aspect of the present invention provides an electronic device, including a memory, a processor, and a program stored on the memory and executable on the processor. When the processor executes the program, it realizes the steps in the method for synergistically stabilizing the wellbore with a wellbore wall stabilizer and temperature-pressure field for marine hydrate drilling as described above.

[0094] The beneficial effects of the present invention are as follows:

[0095] By establishing a multi-field coupling model of fluid-solid-thermal-chemical in marine natural gas hydrate drilling, comprehensively applying knowledge such as rock elastoplastic mechanics, fluid mechanics, heat transfer, and computational mathematics, combining the influence law of the change of the wellbore wall stabilizer concentration in the drilling fluid on the mud cake performance, and the influence law of the temperature-pressure conditions of the wellbore-reservoir on the mechanical parameters of the wellbore wall, the improved Mohr-Coulomb yield criterion is used to accurately calculate the wellbore yield expansion rate and quantitatively evaluate the stability state of the wellbore wall. By dynamically adjusting the dosage of the wellbore wall stabilizer in the drilling fluid and the temperature-pressure parameters, the wellbore stability state is realized, effectively solving the problem of wellbore instability caused by hydrate decomposition, and providing a theoretical basis and technical support for the accurate judgment and dynamic regulation of wellbore stability in complex reservoirs of marine natural gas hydrates. Description of the Drawings

[0096] The drawings are used to provide a further understanding of the present invention, and constitute a part of the specification, and are used together with the embodiments of the present invention to explain the present invention, and do not constitute a limitation to the present invention. In the drawings:

[0097] Figure 1 Shows a flowchart of an embodiment of a method for synergistically stabilizing the wellbore with a wellbore wall stabilizer and temperature-pressure field for marine hydrate drilling of the present invention;

[0098] Figure 2Shows the horizontal well parameters and the schematic diagram of the effect of the wall stabilizer for a method of synergistically stabilizing the wellbore with the wall stabilizer for marine hydrate drilling fluid and the temperature-pressure field in an embodiment of the present invention;

[0099] Figure 3 Shows the variation diagram of the wellbore yield area with time in an embodiment of the method of synergistically stabilizing the wellbore with the wall stabilizer for marine hydrate drilling fluid and the temperature-pressure field of the present invention;

[0100] Figure 4 Shows the law diagram of the influence of the wall stabilizer on the yield area in an embodiment of the method of synergistically stabilizing the wellbore with the wall stabilizer for marine hydrate drilling fluid and the temperature-pressure field of the present invention. Detailed implementation manners

[0101] The present invention will be further described below by way of embodiments in conjunction with the drawings, but is not limited thereto.

[0102] Embodiment 1:

[0103] Taking the drilling well in the hydrate reservoir in a certain sea area as an example, as Figure 1 shown, a method of synergistically stabilizing the wellbore with the wall stabilizer for marine hydrate drilling fluid and the temperature-pressure field includes the following steps:

[0104] Step S1, obtain the current drilling parameters and the physical property data of the natural gas hydrate reservoir, and establish an unsteady mass and heat transfer model of the wellbore-hydrate reservoir through an unsteady heat transfer model of the wellbore-hydrate reservoir, a multiphase seepage model of the hydrate reservoir, and an intrinsic decomposition kinetic model of the hydrate.

[0105] The unsteady heat transfer model of the wellbore-hydrate reservoir is calculated according to the following formula. According to the law of conservation of energy, the solid-phase energy equation with hydrate phase change is:

[0106] (1)

[0107] In the formula, ϕ wg is the limited porosity of gas-liquid flow in the hydrate reservoir, ϕ wg = ϕ ×(1 - S h ), ϕ is the porosity of the sand body, S h is the saturation of the hydrate; t is time; is the equivalent product of the density ρ and the specific heat capacity C of the solid phase, k eh is the equivalent thermal conductivity of the solid phase, and keh It can be solved by volume fraction weighting; T e is the solid phase temperature; ∆ E h is the decomposition heat of hydrate; h sf is the convective heat transfer coefficient between the solid phase and the fluid; A sf is the specific surface area in the porous medium; T f is the fluid temperature; is the decomposition rate of hydrate in the porous medium, which can be solved by the intrinsic decomposition kinetic model of hydrate (K - B model):

[0108] (2)

[0109] In the formula, M h is the molar mass of hydrate, k d is the intrinsic reaction constant of hydrate, △ E is the activation energy of hydrate, R is the gas constant, T is the thermodynamic temperature, A h is the mass transfer specific surface area of hydrate phase change, p eq and p e are the equilibrium pressure of hydrate under the phase equilibrium temperature and pressure conditions and the pore pressure during the formation process, respectively.

[0110] The flow of fluid in the porous medium involves 5 forms of heat transfer, namely, the energy migration caused by fluid flow, the heat conduction inside the fluid, the convective heat transfer at the fluid - solid interface, the Joule - Thomson effect of gas, and the energy decomposition of water and gas, as shown in Equation (3). The left - hand side term of the equation represents the change in internal energy, and the right - hand side represents the 5 forms of heat transfer in sequence.

[0111] (3)

[0112] In the formula, k f is the thermal conductivity of the fluid; p is the fluid pressure; and are the rates of free gas and water generated by hydrate decomposition, respectively; C p,g and C p,w are the specific heat capacities at constant pressure of free gas and water, respectively; S , ρ andv They are the saturation, density, and flow velocity respectively, and the subscripts g and w represent free gas and water respectively; μ JT is the Joule-Thomson effect coefficient.

[0113] In the local non-equilibrium heat transfer model, the energy control equations of the fluid and solid are often closed by constructing the interfacial convective heat transfer mode, and the expression is:

[0114] (4)

[0115] In the formula, N u is the Nusselt number, d p is the average diameter of the sand grains, R e is the Reynolds number, P r is the Prandtl number.

[0116] The multiphase seepage model of the hydrate reservoir is calculated according to the following formula. According to the law of conservation of mass, the continuity equations of free gas, water, and hydrate in the porous medium can be expressed as:

[0117] (5)

[0118] (6)

[0119] (7)

[0120] In the formula, k is the effective permeability of the hydrate reservoir, which has an exponential relationship with the saturation of the hydrate, k = k 0×(1 - S h ) N , k 0 is the effective initial permeability of the hydrate reservoir, N is the permeability reduction index related to the pore scale and structure of the hydrate sediment; ρ h is the density of the hydrate; k rw and k rg are the relative permeabilities of the water phase and the gas phase respectively; μ w and μ g are the viscosities of the water phase and the gas phase respectively; p w and p gare the pressures of the aqueous and gaseous phases within the pores, respectively; the subscript h represents hydrate, S h is the hydrate saturation; 、 and represent the mass change rates of water, gas, and hydrate, respectively; g is the acceleration due to gravity, m / s 2 ; ɸ is the porosity.

[0121] Assuming that the density of water remains constant within the reservoir pressure range, the continuity equation for the aqueous phase after transformation is:

[0122] (8)

[0123] In the formula, p c is the capillary force.

[0124] According to the gas state equation, the continuity equation for the gas phase is finally expressed as:

[0125] (9)

[0126] In the formula, M g is the molar mass of the gas; Z is the gas compressibility factor.

[0127] By coupling the wellbore-hydrate reservoir unsteady heat transfer model, the multi-phase seepage model of the hydrate reservoir, and the intrinsic decomposition kinetics model of hydrates, an unsteady mass transfer and heat transfer model of the wellbore-hydrate reservoir is established as:

[0128] (10)

[0129] Step S2: Considering the changes in reservoir mechanical parameters caused by hydrate phase change, formation creep, and the interaction between drilling fluid and hydrate reservoir, embed the mud cake into the unsteady mass transfer and heat transfer model to construct a multi-field coupling model of drilling fluid-solid-heat-chemistry for marine natural gas hydrates.

[0130] Under the original formation state, hydrates, as an effective cementing component of the formation and the rock skeleton, jointly support the overlying stress of the formation. When hydrates decompose, the phase change from solid to fluid state will change the effective stress of the formation, thereby weakening the cementing strength of the reservoir and deteriorating the mechanical properties of the formation. As a result, problems such as formation instability and a large amount of sand production are very likely to occur. Considering the continuously changing mechanical properties of the hydrate reservoir, an elastoplastic constitutive equation is used to describe the relationship between stress and strain. Its incremental form is as follows:

[0131] (11)

[0132] Wherein, d σij is the effective stress increment matrix; D ijkl is the elastoplastic matrix tensor of the hydrate formation; d εkl is the reservoir skeleton strain increment matrix.

[0133] The static equilibrium equation can be expressed in the tensor form of effective stress as:

[0134] (12)

[0135] Wherein, σ ij is the reservoir skeleton stress tensor, represents the divergence of the stress tensor in the j direction, α B is the Biot coefficient; δ ij is the Kronecker function; F i is the body force load.

[0136] The relationship between the displacement and the strain can be expressed in the tensor form as:

[0137] (13)

[0138] Wherein, ε ij is the reservoir skeleton strain tensor, w is the strain displacement, is the rate of change of the strain displacement along the coordinate i direction, is the rate of change of the strain displacement along the coordinate j direction.

[0139] The changes in the elastic modulus and the internal friction angle caused by the hydrate decomposition will also cause wellbore instability. The relationship between the in-situ friction angle and the hydrate saturation is obtained by regression according to the following formula:

[0140] (14)

[0141] Wherein, φ is the in-situ friction angle of the hydrate reservoir.

[0142] The relationship between the in-situ cohesion and the hydrate saturation is obtained by regression according to the following formula:

[0143] (15)

[0144] Wherein, C (S h ) is the cohesion, C 0 is S h the cohesion when = 0, α , β both are empirical coefficients characterizing the cohesion of the formation.

[0145] The relationship between the elastic modulus of the formation and the hydrate saturation is obtained by regression calculation according to the following formula:

[0146] (16)

[0147] In the formula, E ( S h ) is the elastic modulus of the hydrate reservoir, E 0 is S h the elastic modulus when = 0.

[0148] During the drilling process, the mud cake, as a key product of the interaction between the wellbore wall and the drilling fluid, plays an important role in the stability of the wellbore. On the one hand, the porosity and permeability of the mud cake determine its barrier effect on fluid penetration, directly affecting the risk of hydrate decomposition and wellbore wall failure; on the other hand, the mechanical strength of the mud cake is the microscopic basis for supporting the stability of the wellbore wall. Therefore, it is necessary to introduce mud cake parameters into the multi-field coupling model to further explore the dynamic correlation between the mud cake and the mechanical properties of the reservoir, so as to realize the global analysis of the wellbore wall stability.

[0149] The dynamic permeability of the mud cake is calculated according to the following formula:

[0150] (17)

[0151] In the formula, λ is the pore permeability attenuation index, K mc0 is the minimum permeability of the mud cake, K f is the formation permeability.

[0152] The dynamic porosity of the mud cake is calculated according to the following formula:

[0153] (18)

[0154] In the formula, ϕ mc0 is the minimum porosity of the mud cake, ϕ f is the formation porosity.

[0155] Dynamic porosity and permeability are usually interrelated. For example, a decrease in porosity (through compaction and consolidation) leads to a reduction in permeability. This interaction has a twofold positive effect on the mechanical strength of the mud cake: the decrease in porosity increases the effective stress and enhances the mechanical strength; while the reduction in permeability decreases pore connectivity and enhances the interparticle cementation force, further improving the mechanical strength. Therefore, the change in the dynamic mechanical strength of the mud cake is calculated according to the following formula:

[0156] (19)

[0157] where, σ mc0 is the initial mechanical strength of the mud cake; m and n are the contribution constants of permeability and porosity to the mechanical strength of the mud cake.

[0158] By introducing reservoir mechanical parameters (such as the internal friction angle, cohesion, and elastic modulus) and the changes in the porosity, permeability, and dynamic mechanical strength parameters of the mud cake into the wellbore-hydrate reservoir unsteady mass transfer and heat transfer model, a fully coupled relationship between the thermal field, flow field, and force field is established using the multi-physics field coupling software COMSOL; in the thermal field, the low porosity and low permeability of the mud cake change the heat transfer path near the wellbore by modifying the thermal conductivity and heat capacity of the local reservoir area; in the flow field, the barrier effect of the mud cake affects the seepage behavior of the fluid and the pore pressure distribution after hydrate decomposition through the dynamic correction of the effective permeability and porosity; in the force field, the dynamic mechanical strength of the mud cake, as an important source of wellbore support, acts together with the changes in reservoir mechanical parameters to affect the stress distribution and plastic zone evolution around the wellbore. By comprehensively coupling the reservoir porosity, permeability, and the heat release, fluid flow, and mechanical evolution processes caused by hydrate decomposition, a multi-field coupling model integrating mass transfer, heat transfer, mechanical behavior, and chemical reactions is finally formed, providing a theoretical basis for studying the mechanism of wellbore instability and stability control during the drilling process of marine natural gas hydrates.

[0159] Step S3, design a marine hydrate drilling fluid system, add different dosages of wall stabilizers to the drilling fluid, analyze the dynamic evolution laws of key parameters such as the porosity, permeability, and mechanical strength of the mud cake, and clarify the influence mechanism of the drilling fluid wall stabilizer on the reservoir mechanical properties.

[0160] Obtain the existing conventional wall stabilizers for marine hydrate drilling fluids (the wall stabilizer in this example is produced by Beijing Kenuojie Energy & Environmental Protection Technology Co., Ltd.), and systematically construct a high-performance marine hydrate drilling fluid system with both wellbore stability and reservoir protection by adding lubricants, inhibitors, viscosity increasing and encapsulating agents, viscosifiers, glass beads, filtration loss reducers, and reservoir bridging agents. By changing the concentration of the wall stabilizer in the drilling fluid, clarify the influence mechanism of the drilling fluid wall stabilizer on the reservoir mechanical properties.

[0161] The construction system of this embodiment is: seawater + 0.1% NaOH + 7% NaCl + 3% CaCl2 + 3% BLWZ (glass microspheres) + 2% PF-FLOTROL (filtrate reducer) + 0.1% PF-XC (xanthan gum) + 2% PF-EZCARB (reservoir plugging agent) + 1% wall stabilizer + 0.1% PF-PLUS (viscosity increasing and encapsulating agent) + 3% PF-UHIB (polyamine) + 2% PF-HLUB (mud cake lubricant) + 2% PF-LUBE (lubricant) + 1% SYZ-2 (hydrate formation inhibitor).

[0162] Measure the density and rheological parameters of the drilling fluid and conduct the API filtration experiment. Pour the drilling fluid into the filter loss instrument, install the filter paper or filter membrane, turn on the equipment, and maintain operation for 30 minutes under the set conditions. Record the cumulative filtrate volume 𝑉 every 1 minute, and calculate the filtration loss. Turn off the equipment, slowly release the pressure, take out the mud cake, and use a thickness gauge to measure the thickness at multiple positions of the mud cake and take the average value L 。

[0163] Place the mud cake in an oven, set the temperature (such as 60 °C), dry it to a constant weight, and then measure the porosity of the mud cake using the density method, that is, measure the dry weight ( m d ), and volume ( V ), calculate the dry density of the mud cake ( ρ d = m d / V ), and calculate the porosity through the bentonite density ( ρ s ) of the mud preparation is:

[0164] (20)

[0165] In the filtration experiment, under the action of a certain pressure difference, the drilling fluid forms a mud cake through the filter paper or filter membrane, and the filtrate flows out through the mud cake. The flow of the filtrate and the formation process of the mud cake conform to Darcy's law and filtration theory. The permeability of the mud cake affects the passing speed of the filtrate. Conversely, the change of the filtrate volume with time also reflects the permeation characteristics of the mud cake.

[0166] According to the filtration theory and Darcy's law, calculate the permeability of the mud cake K is:

[0167] (21)

[0168] In the formula: V is the filtrate volume, cm³; μ is the plastic viscosity of the drilling fluid, Pa·s; Lis the mud cake thickness, m; t is the experimental time, s; A is the filter paper area, m 2 ; Δ P is the pressure difference, Pa.

[0169] Use the FCP Mud Cake Penetration Tester to measure the mechanical strength of the mud cake. This device can accurately measure mechanical properties such as its compressive strength while maintaining the integrity of the mud cake. Install the mud cake sample to be tested on the test bench of the FCP instrument, ensure that the needle is vertically aligned with the sample surface, select an appropriate load range according to the experimental requirements and calibrate the instrument to ensure measurement accuracy. After starting the instrument, slowly apply the preset load and record the relationship curve between the penetration depth and the applied force. To improve the reliability of the data, perform at least three repeated tests at each measurement point and take the average value. Finally, calculate the compressive strength of the mud cake by analyzing the load-penetration depth curve.

[0170] The compressive strength reflects the bearing capacity of the mud cake under axial pressure. A higher compressive strength indicates that the mud cake forms a strong barrier on the wellbore wall, which helps prevent accidents such as well collapse and well kick. The compressive strength of the mud cake σ c The calculation formula is:

[0171] (22)

[0172] In the formula: F max is the maximum applied load value, N; r is the needle radius, m.

[0173] Adjust the concentration of the wellbore stabilizer in the drilling fluid and conduct filtration experiments, porosity determination, permeability tests, and mechanical strength measurements under the same experimental conditions. By combining the experimental data with reservoir mechanics theory and the multi-field coupling model of drilling fluid-solid-thermal-chemical in the marine natural gas hydrate drilling, systematically analyze the dynamic evolution laws of mud cake porosity, permeability, and mechanical strength, and reveal how the wellbore stabilizer affects the macroscopic mechanical properties of the reservoir by regulating the microscopic structure parameters of the mud cake during the optimization of the drilling fluid formula, so as to clarify the influence mechanism of the wellbore stabilizer on the reservoir mechanical properties. The experimental and calculation results are shown in Table 1.

[0174] Table 1 Experimental calculation results

[0175]

[0176] G` and G`` are two of the values in the experiment for measuring the viscosity of the drilling fluid (initial shear value and final shear value).

[0177] Step S4: Dynamically adjust the dosage of the drilling fluid wall stabilizer and the temperature and pressure parameters of the drilling fluid, and judge the wellbore stability state in real time according to the improved Mohr-Coulomb criterion for the hydrate formation, so as to achieve the wellbore stability of the drilling in the marine hydrate reservoir.

[0178] After clarifying the regulation mechanism of the wall stabilizer on the microscopic structure of the mud cake and the macroscopic mechanical properties of the reservoir, further dynamically adjust the concentration of the drilling fluid wall stabilizer and the parameters such as the temperature and pressure of the drilling fluid, and combine with the multi-field coupling model of drilling fluid-solid-thermal-chemical in the marine natural gas hydrate drilling to evaluate the wellbore stability performance in real time. Based on the improved Mohr-Coulomb yield criterion and the wellbore yield expansion rate (plastic yield distance ∆ r / wellbore radius r 0), quantify the plastic yield range of the wellbore to optimize the dynamic regulation scheme and accurately judge the wellbore stability state.

[0179] The basis for judging the wellbore stability by applying the improved Mohr-Coulomb yield criterion for the hydrate formation into the multi-field coupling model of drilling fluid-solid-thermal-chemical in the marine natural gas hydrate drilling:

[0180] (23)

[0181] In the formula: τ is the shear stress, MPa; σ is the confining pressure, MPa;

[0182] Under different stress states, the expression of the critical maximum principal stress of the hydrate formation is:

[0183] (24)

[0184] In the formula, σ 1f is the critical maximum principal stress, σ 3 is the minimum effective principal stress.

[0185] Calculate the maximum effective principal stress σ 1:

[0186] (25)

[0187] In the formula, P mud is the wellbore drilling fluid pressure, MPa; P rock is the formation pore pressure, MPa; r 0 is the wellbore radius, m; r is the radial distance from the wellbore center, m.

[0188] Calculate the minimum effective principal stress σ 3:

[0189] (26)

[0190] If σ 1f >[[]] σ σ 1, the formation in this area is in the stage of cumulative plastic deformation, and this point is the yield boundary. At this time, the radial distance ∆ r from the wellbore center is the plastic yield distance.

[0191] It can be seen from the Mohr-Coulomb yield criterion of the hydrate formation that the convective heat transfer between the wellbore and the reservoir under the action of pressure difference triggers the decomposition of hydrates in the near-wellbore area, resulting in the deterioration of the mechanical properties of the reservoir, that is, the reduction of the mechanical parameters around the wellbore, causing the near-wellbore area to evolve from elastic strain to plastic yield, and the wellbore yield expansion rate (plastic yield distance ∆ r / wellbore radius r 0) gradually increases with the decomposition of hydrates, triggering wellbore instability.

[0192] From Figure 2 it can be known that the change of the concentration of the drilling fluid wall-building agent can directly affect the porosity, permeability and mechanical strength of the mud cake. By optimizing the dosage of the wall-building agent, the mud cake parameters can be adjusted, so as to enhance the plugging and bearing performance of the near-well area of the reservoir. At the same time, by changing the temperature and pressure parameters of the drilling fluid, the decomposition rate of hydrates can be inhibited and the pressure difference between the wellbore and the reservoir can be reduced, and the range of plastic yield of the wellbore can be decreased.

[0193] Based on the multi-field coupling model of drilling fluid-solid-thermal-chemical for offshore natural gas hydrates, combined with parameters such as the temperature and pressure conditions of the reservoir and the wellbore, the concentration of the wall-building agent, and the properties of the mud cake, the wellbore yield expansion rate is calculated. When the yield expansion rate exceeds the set threshold (such as 0.3), by dynamically adjusting the drilling fluid parameters (concentration of the wall-building agent, drilling fluid temperature or pressure), the risk of wellbore instability can be quickly reduced, and the stability of the wellbore during offshore hydrate drilling can be achieved.

[0194] In this embodiment, as Figure 3 shown, the yellow in the figure is the unyielded area, and the blue is the yielded area. When there is no wall-building agent in the drilling fluid system, in the initial stage of drilling fluid invasion (within 1 h), the formation does not plastically yield, and the change range of hydrate saturation is small. However, with the continuous invasion of the drilling fluid, the range of temperature and pressure disturbance around the wellbore gradually expands, the hydrates decompose continuously, the cementing ability of the formation gradually decreases, and the reservoir begins to yield and the area continues to increase. After 20 h, the wellbore yield expansion rate reaches 90%, seriously endangering the well control safety of drilling. As Figure 4 shown, the increase of the concentration of the wall-building agent in the drilling fluid system can reduce the wellbore yield expansion rate and the risk of wellbore instability. Of course, the final dosage still needs to consider the influence of the rheological filtration performance parameters of the drilling fluid.

[0195] In summary, by fully considering the influence of the drilling fluid system and performance parameters on the wellbore mud cake, the established multi-field coupling model of drilling fluid-solid-thermal-chemical for marine natural gas hydrate is more in line with the actual situation, completing the accurate judgment and dynamic regulation scheme of wellbore stability in deep-water complex formations, and providing strong help for the flexible on-site design of high-performance drilling fluid systems and performance parameters.

[0196] Example 2

[0197] A method for synergistically stabilizing the wellbore with a wall stabilizer and temperature-pressure field for a drilling fluid in marine hydrate drilling, including a data acquisition module, a data analysis module, and a dynamic regulation module; the data acquisition module is used to collect key performance parameters of the hydrate reservoir, wellbore drilling fluid, and wellbore mud cake; the data analysis module is used to execute the method for synergistically stabilizing the wellbore with the wall stabilizer and temperature-pressure field, establish a multi-field coupling model of drilling fluid-solid-thermal-chemical for marine natural gas hydrate, and calculate the wellbore yield expansion rate based on the improved Mohr-Coulomb yield criterion to quantify the wellbore stability state; the dynamic regulation module realizes the accurate regulation of wellbore stability by adjusting the concentration of the drilling fluid wall stabilizer and the temperature-pressure parameters of the drilling fluid, providing theoretical support and technical guarantee for the prevention and dynamic control of wellbore instability during marine hydrate drilling.

[0198] Example 3

[0199] A computer-readable storage medium, on which a program is stored, and when the program is executed by a processor, it realizes the steps in a method for synergistically stabilizing the wellbore with a wall stabilizer and temperature-pressure field for a drilling fluid in marine hydrate drilling as described in Example 1.

[0200] Example 4

[0201] An electronic device, including a memory, a processor, and a program stored on the memory and executable on the processor, and when the processor executes the program, it realizes the steps in a method for synergistically stabilizing the wellbore with a wall stabilizer and temperature-pressure field for a drilling fluid in marine hydrate drilling as described in Example 1.

[0202] The above embodiments are only illustrative of the principles and effects of the present invention, and are not used to limit the present invention. Any person familiar with this technology can modify or change the above embodiments without departing from the spirit and scope of the present invention. Therefore, all equivalent modifications or changes completed by those with ordinary knowledge in the technical field without departing from the spirit and technical ideas disclosed by the present invention should still be covered by the claims of the present invention.

Claims

1. A method for synergistically stabilizing the wellbore with a wellbore wall stabilizer for marine hydrate drilling drilling fluid and temperature and pressure fields, characterized in that, It includes the following steps: Step S1: Obtain the current drilling parameters and physical property data of the natural gas hydrate reservoir, and establish an unsteady mass and heat transfer model of the wellbore-hydrate reservoir through the unsteady heat transfer model of the wellbore-hydrate reservoir, the multiphase seepage model of the hydrate reservoir, and the intrinsic decomposition kinetic model of hydrates; Step S2: Considering the changes in reservoir mechanical parameters brought about by hydrate phase change, formation creep, and the interaction between drilling fluid and hydrate reservoir, embed the mud cake into the unsteady mass and heat transfer model to construct a multi-field coupling model of drilling fluid-solid-thermal-chemical in the marine natural gas hydrate drilling; Considering the continuously changing mechanical properties of the hydrate reservoir, the elastoplastic constitutive equation is used to describe the relationship between stress and strain, and its incremental form is as follows: dσ ij = D ijkl dε kl (11) where d σij is the effective stress increment matrix; D ijkl is the elastoplastic matrix tensor of the hydrate formation; d εkl is the reservoir skeleton strain increment matrix; The static equilibrium equation is expressed in the tensor form of effective stress as: σ ij,j -(α B δ ij p) ,j +F i =0(12) where, σ ij is the reservoir skeleton stress tensor, σ ij,j represents the divergence of the stress tensor in the j direction, and α B is the Biot coefficient; δ ij is the Kronecker function; F i is the body force load, and p is the fluid pressure; The relationship between displacement and strain can be expressed in tensor form as: where ε ij is the reservoir skeleton strain tensor, w is the strain displacement, and w i,j is the change rate of the strain displacement along the coordinate i direction, and w j,i is the change rate of the strain displacement along the coordinate j direction; Calculate and regress the relationship between the in-situ friction angle and hydrate saturation according to the following formula: In the formula, is the internal friction angle of the hydrate reservoir, and S h is the saturation of the hydrate; Calculate and regress the relationship between the in-situ cohesion and hydrate saturation according to the following formula: where, C(S h ) is the cohesive force, C0 is the cohesive force when S h = 0, and both α and β are empirical coefficients characterizing the cohesive force of the formation; Calculate and regress the relationship between the formation elastic modulus and hydrate saturation according to the following formula: lgE(S h ) = lgE0 + 1.1983S h (16) where E(S h ) is the elastic modulus of the hydrate reservoir, and E0 is the elastic modulus when S h = 0; Calculate the dynamic permeability of the mud cake according to the following formula: where λ is the pore permeability attenuation index, K mc0 is the minimum permeability of the mud cake, K f is the formation permeability, and t is the time; Calculate the dynamic porosity of the mud cake according to the following formula: where φ mc0 is the minimum porosity of the mud cake, and φ f is the formation porosity; Calculate the change in the dynamic mechanical strength of the mud cake according to the following formula: where σ mc0 is the initial mechanical strength of the mud cake; m and n are the contribution constants of permeability and porosity to the mechanical strength of the mud cake; By introducing the in-situ friction angle, in-situ cohesion, elastic modulus, and the porosity, permeability, and change in dynamic mechanical strength of the mud cake into the unsteady mass and heat transfer model of the wellbore-hydrate reservoir, use the multi-physics field coupling software COMSOL to establish a full coupling relationship between the thermal field, flow field, and force field; Step S3: Design a marine hydrate drilling fluid system, add different dosages of wall-building agents to the drilling fluid, analyze the dynamic evolution laws of the porosity, permeability, and mechanical strength of the mud cake, and clarify the influence mechanism of the drilling fluid wall-building agent on the reservoir mechanical properties; Obtain the existing wall-building agents for conventional marine hydrate drilling fluids, systematically construct a marine hydrate drilling fluid system by adding lubricants, inhibitors, viscosity increasing and encapsulating agents, viscosifiers, glass beads, filtration loss reducers, and reservoir bridging agents, measure the density and rheological parameters of the drilling fluid and conduct API filtration experiments. Pour the drilling fluid into the filter loss instrument, install filter paper or filter membrane, turn on the equipment, maintain the operation for 30 minutes under the set conditions. If the cumulative filtrate volume V is recorded every 1 minute, calculate the filtration loss; turn off the equipment, release the pressure, take out the mud cake, use a thickness gauge to measure the thickness at multiple points of the mud cake, and take the average value L; Place the mud cake in an oven, set the temperature, dry it to a constant weight, and then measure the porosity of the mud cake by the density method, that is, measure the dry weight m of the mud cake d and volume V, and calculate the dry density ρ d = m d / V. Through the density ρ s of bentonite in the mud preparation, calculate the porosity φ as follows: According to the filtration theory and Darcy's law, calculate the permeability K of the mud cake as: Where: V is the filtrate volume, cm 3 ; μ is the plastic viscosity of the drilling fluid, Pa·s; L is the mud cake thickness, m; t is the experimental time, s; A is the filter paper area, m 2 ; ΔP is the pressure difference, Pa; Use an FCP mud cake penetrometer to measure the mechanical strength of the mud cake. Install the mud cake sample to be tested on the test bench of the FCP instrument, ensure that the needle is vertically aligned with the sample surface, select the load range according to the experimental requirements and calibrate the instrument. After starting the instrument, apply the preset load and record the relationship curve between the penetration depth and the applied force; finally, calculate the compressive strength of the mud cake by analyzing the load-penetration depth curve; The compressive strength σ of the mud cake c The calculation formula is as follows: where: F max is the maximum applied load value, N; r is the needle radius, m; Adjust the concentration of the wall-building agent in the drilling fluid, and conduct filtration experiments, porosity measurements, permeability tests, and mechanical strength measurements under the same experimental conditions. By combining the experimental data with reservoir mechanics theory and the multi-field coupling model of drilling fluid-solid-thermal-chemical in marine natural gas hydrate reservoirs, systematically obtain the dynamic evolution laws of mud cake porosity, permeability, and mechanical strength, and reveal how the wall-building agent affects the macroscopic mechanical properties of the reservoir by regulating the microscopic structure parameters of the mud cake during the optimization of the drilling fluid formula; When measuring the mechanical strength of the mud cake using an FCP mud cake penetrometer, at least three repeated tests are performed at each measurement point, and the average value is taken; Step S4: Dynamically adjust the addition amount of the drilling fluid wall-building agent and the temperature and pressure parameters of the drilling fluid, and judge the wellbore stability state in real time according to the improved Mohr-Coulomb criterion for hydrate formations, so as to achieve the stability of the wellbore during drilling in marine gas hydrate reservoirs; Based on the improved Mohr-Coulomb yield criterion and the wellbore yield expansion rate, quantify the plastic yield range of the wellbore. The wellbore yield expansion rate = plastic yield distance Δr / wellbore radius r0; Use the improved Mohr-Coulomb yield criterion for hydrate formations embedded in the multi-field coupling model of drilling fluid-solid-thermal-chemical in marine natural gas hydrate reservoirs as the basis for judging wellbore stability: In the formula: τ is the shear stress, MPa; σ is the confining pressure, MPa; Under different stress states, the expression of the critical maximum principal stress of the hydrate formation is: where σ 1f is the critical maximum principal stress, and σ3 is the minimum effective principal stress; Calculate the maximum effective principal stress σ1 through the stress distribution of the reservoir: Where P mud is the wellbore drilling fluid pressure, MPa; P rock is the formation pore pressure, MPa; r0 is the wellbore radius, m; r is the radial distance from the wellbore center, m; Calculate the minimum effective principal stress σ3 through the stress distribution of the reservoir: If σ 1f > σ1, the formation in this area is in the stage of plastic deformation accumulation. This point is the yield boundary, and the radial distance Δr from the wellbore center at this time is the plastic yield distance; It can be seen from the Mohr-Coulomb yield criterion of the hydrate formation that the convective heat transfer between the wellbore and the reservoir under the action of the pressure difference causes the decomposition of hydrates in the near-wellbore area, resulting in the deterioration of the mechanical properties of the reservoir, that is, the reduction of the mechanical parameters around the wellbore, causing the near-wellbore area to evolve from elastic strain to plastic yield, and the wellbore yield expansion rate increases with the decomposition of hydrates, leading to wellbore instability; Optimize the mud cake parameters by adjusting the addition amount of the wall-building agent, so as to enhance the plugging and bearing performance in the near-well area of the reservoir; at the same time, change the temperature and pressure parameters of the drilling fluid to inhibit the hydrate decomposition rate and reduce the pressure difference between the wellbore and the reservoir, and reduce the range of plastic yield of the wellbore; based on the multi-field coupling model of drilling fluid-solid-thermal-chemical in marine natural gas hydrate reservoirs, combined with the temperature, pressure conditions of the reservoir and wellbore, the concentration of the wall-building agent, and the performance parameters of the mud cake, calculate the wellbore yield expansion rate. When the yield expansion rate exceeds the set threshold, quickly reduce the risk of wellbore instability by dynamically adjusting the drilling fluid parameters, and achieve the stability of the wellbore during drilling in marine gas hydrates. The drilling fluid parameters include the concentration of the wall-building agent, the temperature of the drilling fluid, and the pressure of the drilling fluid.

2. A wellbore wall stabilizing system that synergistically stabilizes the wellbore with a wellbore wall solidifying agent for marine hydrate drilling drilling fluid, characterized in that, It includes a data acquisition module, a data analysis module and a dynamic regulation module; each module executes the steps in a method for synergistically stabilizing the wellbore with a wall stabilizer and a temperature-pressure field for marine hydrate drilling mud as described in claim 1; the data acquisition module is used to collect key performance parameters of the hydrate reservoir, wellbore drilling mud and wellbore mud cake; the data analysis module is used to execute the method for synergistically stabilizing with the wall stabilizer and the temperature-pressure field, establish a multi-field coupling model of drilling fluid-solid-thermal-chemical for natural gas hydrate drilling in the sea area, and calculate the wellbore yield expansion rate based on the improved Mohr-Coulomb yield criterion to quantify the wellbore stability state; the dynamic regulation module realizes the regulation of wellbore stability by adjusting the concentration of the drilling fluid wall stabilizer and the temperature-pressure parameters of the drilling fluid.

3. A computer-readable storage medium, characterized in that, A program is stored thereon, and when the program is executed by a processor, it realizes the steps in a method for synergistically stabilizing the wellbore with a wall stabilizer and a temperature-pressure field for marine hydrate drilling mud as described in claim 1.

4. An electronic device, including a memory, a processor and a program stored on the memory and executable on the processor, and when the processor executes the program, it realizes the steps in a method for synergistically stabilizing the wellbore with a wall stabilizer and a temperature-pressure field for marine hydrate drilling mud as described in claim 1.

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